This thesis proposes the challenges on availing Multi terminal HVDC in largest India's network

1. TRANSIENT STABILITY ANALYSIS OF MULTI-
INFEED HVDC SYSTEM of AGRA-BHIWADI-DADRI
INVERTER TO AC NATIONAL GRID
Report Thesis
By
S. Naresh Ram
ET17 (02781)
POWERGRID CORPORATION OF INDIA LIMITED
±800 KV 6000MW Multi Terminal NEA/APD interconnector
HVDC project -1
Head of Department: C.Nandy
Chief Manager

2. ABSTRACT:
Voltage collapse in electric power systems have caused blackouts around the
world, although the exact mechanism of a voltage collapse is still a matter of investigation, it is
known that in such events the voltage magnitudes at electric power systems decrease rapidly
under a heavy load , From a more fundamental point of view, the ubiquitous presence of
bifurcations in the dynamic behaviour of nonlinear electric power systems may be related to the
occurrence of voltage collapses . In this picture, a normal operation of the power system would
correspond to a stable equilibrium state. When the production or transmission of electric energy is
insufficient to supply an increasing power demand, an electric power system may lose its
operational stability .
There are serious concerns relating to a Multi-Infeed HVDC system when
feeding a weak AC network. Typical issues concerning multi-infeed configurations are: need for
coordination of the recovery control, need for different DC modulation strategies to stabilize the
system, possibility of voltage instability of the area receiving large amount of power from
multiple HVDC links and the risk of mutual commutation failures. In contrast, if the area
receiving electrical power from multiple HVDC transmission links is relatively strong due to the
presence of large amount of generation units nearby there are still some questions that need to be
investigated such as the issues underlining the operation of such a multi-infeed system, the proper
design of the controls of the HVDC systems and the system dynamic performance under extreme
contingencies. This report investigates into an example of such a multi-infeed HVDC system. The
author have performed small signal analysis of the system to assess instability associated with the
control modes. Electromechanical and voltage stability analysis were performed for harmful
contingencies.
This system (Agra-Bhiwadi-dadri) is chosen for the study of integration issues
that are present in multiinfeed HVDC system. This report deals with the computation of the
multiinfeed interaction parameters which are newly introduced Multi Infeed Interaction Factor
(MIIF), Multi Infeed Effective Short Circuit Ratio(MIESCR) for multiinfeed northern region
system in India.

3. List of Figures and Tables:
1. Fig 1 India Map with All present HVDC systems
2. Fig 2 Single line diagram of the reduced network
3. Fig 1.2.1. Bipole with One Single 12-pulse Converter
4. Fig 1.2.2: A bipole with Two 12 pulse Converter
5. Fig 1.2.3. A Bipole with Two Parallel Converters per Pole
7. Fig 3 Single phase 2 winding transformer
8. Fig 4: Simple diagram of Entire project.
9. Figure 1.3.2 Low resistance ground fault
10. Figure 1.3.3 High resistance ground fault
11. Fig. 2.1.2 Maximum Power Curve for γ minimum
12. Fig. 2.2.1 The simplified diagram of single HVDC link.
13. Table 1. All existing Hvdc power/voltage/ location
14. Table 2: MIIF Matrix for the three inverters Agra, Bhiwadi and Dadri
15 Fig 2.3.3 single line for both HVDC and AC line to Generator .
16 Fig 5 graph of ( ) i.e load angle with time

4. CONTENTS:
1.Multi Infeed HVDC System Description
PAGE NO:
1.1 INTRODUCTION 1
1.2 ±800KV NEA HVDC Multi Terminal Project Design outline
1.2.1 A Bipole with One Single 12-Pulse Converter per Pole 2
1.2.2 A Bipole with Two 12-Pulse Series Converters per Pole 3
1.2.3 A Bipole with Two Parallel Converters per Pole 4
1.3 HVDC line Fault Analysis:
1.3.1 Time domain reflectometer (TDR) 6
1.3.2 Low resistance to ground 6
1.3.3 High resistance to ground 7
2.Multi-Infeed Stability Issue
2.1 Maximum Power Curve (MPC) 8
2.2 MPC Application to Simple Model 9
2.3 Interaction indices for multiinfeed HVDC System 10
2.3.1 Multi Infeed Interaction Factor (MIIF) 11
2.3.2 Multi Infeed Effective Short Circuit Ratio (MIESCR) 11
2.3.3 Transient small signal HVDC stability analysis 12
Conclusion and Future work 13

5. 1.Multiinfeed HVDC system description:
1.1 INTRODUCTION:
In India, HVDC links NER-Agra, which is coming up with existing Rihand-Dadri, Balia-Bhiwadi form a multiinfeed
HVDC system. This system is chosen for the study of integration issues that are present in multiinfeed HVDC system.
Fig 1: Map is not to scale:
The network around the 3 HVDC links NER-Agra, Balia-Bhiwadi and Rihand-Dadri is represented in detail, while at
the periphery buses the equivalents are derived to represent the network connected at that bus. The steady-state
conditions as well as the short circuit levels in the integrated network are preserved in the reduced equivalent system
in order to represent a typical operating condition of the system. The Single line diagram of the reduced network
considered for the study is given in Figure 2.
This reduced network is modelled on Real Time Digital Simulator(RTDS) available at CPRI for carrying out the
studies on integration issues of multiinfeed HVDC systems into one AC system.
The reduced network consists of (a) 24 - 400kV Buses, (b) 5 - 800kV Buses, (c) 45- 400kV Transmission Lines,
(d) 3 - 800kV Transmission Lines, (e) 3 - HVDC links, (f) 28 - Equivalent sources, (g) Generators explicitly
modelled (NER) - 3600MW and (h) 20 – loads.
Fig 2: Single line diagram of the reduced network considered for the study
Before going to the Stability analysis of Multifeed, lets have a brief look on India’s large Power transmission
HVDC Multiterminal project.

6. 1.2 ±800KV NEA HVDC Multi Terminal Project Design outline
There are several configurations that can be applied for HVDC converter stations at 800 kV. The choice of a specific
configuration will be dictated by:
• The amount of power to be transmitted
• The transmission distance
• Staging consideration of the project
• The amount of power to be transmitted at the different stages of the project
• Reliability and availability requirements
• Loss evaluation
• Size and weight of the converter transformers for transport
In the following sections the different possible configurations will be presented and discussed in light of the above
considerations. In addition all the operational features of a specific configuration will also be presented.
In all configurations the discussion is limited to bipolar configurations, which means no monopolar system is
envisaged.
1.2.1 A Bipole with One Single 12-Pulse Converter per Pole
The configuration in this case would very similar to the currently used configuration for HVDC bipole rated for 500
kV and has been built for powers up to 3000 MW
The difference here is that even if the rated power is 3000 MW, the transmission distance may be prohibitive to build
the bipole at 500 kV. For 3000 MW power transfer over a distance of 3000 Km, DC voltage of ± 500 kV may not be
feasible.
A Bipolar System with One 12-Pulse Group per Pole at
800 kV
If we consider the factors outlined above and apply them
to this configuration, the following can be observed:
The power to be transmitted can be as high as 6000 MW.
If we consider the starting point as 3000 MW, the DC
current will be 1875 A and if the DC power is 6000 MW
the DC current will be 3750 A. It is clear that the all these
parameters are manageable. The transmission distance is
not an issue.
Fig 1.2.1. Bipole with One Single 12-pulse Converter
• The staging here is limited in building one pole followed by the second pole. In order to limit operation with ground
return mode, bipole DC line will have to be built from the beginning to allow stage one to operate in metallic return
mode. The losses during mono-polar metallic return are doubled compared to monopolar ground return mode of
operation.
• The maximum amount of power to be transmitted if the project is built in two stages will be half the nominal
bipolar power plus over load.
• From a reliability point of view, this is in no way different from the current typical bipole of 3000 MW at 500 kV.
The system has to withstand the loss of a pole rated at 1500 MW. However as we increase the rated power to levels
above 3000 MW, obviously the loss of a pole will result in a larger loss of power so at 6000 MW the loss of a pole
means the loss of 3000 MW. This is quite critical in most systems.
• The loss evaluation here is not an issue. The scheme is operating from the start at the full transmission voltage. The
size and weight of the converter transformers is always a deciding factor. In this case for a bipole rated power of 3000
MW, the converter transformer rating based on single phase two winding units is 278 MVA.
This is a manageable rating for manufacturing and transportation. However if the nominal bipolar power is 4000
MW, the transformer rating will be 370 MVA, leading to very large units. Certainly for a 6000 MW bipole, the
rating of 555 MVA is not feasible

7. 1.2.2 A Bipole with Two 12-Pulse Series Converters per Pole
The voltage rating of the two converters can be the same, which
means the voltage rating is 400 kV per converter, and each handles
half the pole power. Another alternative is two dissimilar voltages
rated 12 pulse converter valve groups, which also means the power
rating of the two 12 pulse converter bridges is different. For example
one converter can be at 500 kV and the second one at 300 kV, or 600
kV and 200 kV. One reason for proceeding in the direction of
the dissimilar rated series converters would be staging the project
and the first stage power required is more than half of the total
transmitted power. For example on a 6000 MW ultimate power and
4500 MW is required for stage 1 and 1500 MW is required for stage
2.
Fig 1.2.2: A bipole with Two 12 pulse Converter
This approach can be used if the time interval between the two stages is long and the investment for the ultimate
capacity can be deferred. However, one has to keep in mind that the cost of losses here will be a major factor in the
evaluation because of operating the first stage at a lower DC voltage.
Obviously this alternative of dissimilar rated converters in series has to be evaluated against other alternatives that
allow the system to operate at full DC voltage during the staging. One has to also to keep in mind that dissimilar series
converters affect the spares required. The discussion for the series converters per pole will concentrate on similar rated
converters. The dissimilar converters operate in the same manner and the reasons for using them have been discussed
above...
• The power to be transmitted can be as high as 6000 MW. This means 1500 MW per 12 pulse converters and 3000
MW per pole. Again the economics will dictate how low the transmitted power can be.
• The transmission distance here is not an issue as long as we are operating at full transmission voltage of 800 kV.
The issue will only arise during outages of one converter in a pole and that pole has to operate at 400 kV.
• For staging of converters there are more choices and flexibility. If we take the example of a 6000 MW bipole, then
stage one can be at ±400 kV and a transmitted power of 3000 MW, depending on the distance. The second stage can
be up to +800 kV and – 400 kV, and a transmitted power of 4500 MW. The final stage can be the ultimate
transmission of capacity of 6000 MW and ±800 kV.
• From a reliability perspective, the system will have higher energy availability than the single converter per pole just
because the loss of one converter, which is the most common fault, only represents 25% of the total capacity.
• The loss evaluation is not an issue for operation at full voltage. However, it has to be considered very carefully if
staging is considered, or if dissimilar series groups are
considered. For example in the case of dissimilar converters of 600 kV and 200 kV, for the loss of the 600 kV
converter in one pole , this pole will be operating at only at 200 kV and full load current.
• The size and the weight of the converter transformers, are quite manageable here, the typical single phase two
winding will be in the order of 278 MVA. From spare transformers point of view four spare units are needed per
station because of the different voltage classes of 800kV, 600 kV, 400 kV and 200 kV. Although there are alternatives
to this.
• There is more flexibility to operate at reduced voltages during any insulation type problems. For example, the poles
can be operated at the typical 0.8 PU DC voltages with two converters per pole or even down to one converter per
pole at 400 kV.
For series connected converters per pole, certain additional switchgear and measuring devices are required because of
the series connection.
As shown in figure, each converter will have a high speed by pass switch. The voltage across the switch is
400 kV DC plus the twelve pulse ripple and is the same for both converters as long as they are similar in rating. The
difference is the insulation to ground. Also each converter will include, anode, cathode and by pass disconnects for
connecting and isolating the converter. The function of the by-pass switch is to allow the deblocking of the converter

8. before it is put in service and to do fast by pass during blocking. The deblock and block of series converters are
completely different from that of the single converter per pole. In addition even if the pole is under shutdown there
will be current in the by pass switches.
1.2.3 A Bipole with Two Parallel Converters per Pole
Even though this is referred to as parallel converters per pole, in principle this can be looked upon as two bipoles with
the same polarity poles connected in parallel.
The configuration is shown in figure
Fig 1.2.3. A Bipole with Two Parallel Converters per Pole.
In the parallel configuration of the two 12 pulse
converters, there are some unique features:
• Each pole is operating always at 800 kV which
means lower losses during any converter outage.
This is different from series connected converters
per pole where the outage of a converter in a pole
reduces the DC voltage in that pole to half (for
similar converter bridges),which means for the same
power there will be higher losses.
• For the same power although the DC line current is
the same for both series and parallel arrangements,
the converter DC current in the parallel arrangement is lower than the series connected converters. This means
there is more room for overload capability on per converter basis based on the current state of the art for thyristor
valves.
. From staging point of view and in particular if the time between stages is long, in the parallel configuration the pole
is always operating at full voltage, which means lower losses. However the staging here can only be done on bipolar
basis. For example for a 6000 MW, it can be in three stages only, stage one 1500 MW single converter at 800 kV and
metallic return, stage two 3000 MW from one bipole, and stage three the complete system at 6000 MW.
. In the parallel configuration, high voltage high speed switches (HVHS) are required one per pole. These switches are
rated for carrying the full load DC current of the converter plus overload, insulated for 800 kV to ground and will
have to withstand 800 kV DC across the switch contacts. However, no DC current interruption capability is required.
. The deblock and block sequences are completely different from the series connected converters.The sequence has to
be able to parallel and de-parallel the converters manually without any disturbance to the other operating pole.
In the event of a converter protection trip, there will be a short interruption to the power from the parallel converter
until the HVHS of the faulted pole is opened.
From a reliability perspective, the system will have similar energy availability as the series converters because the loss
of one converter, which is the most common fault, only represents 25% of the total capacity. In addition because the
current rating of the parallel converter is lower than the series connected converters, and if 5 inch thyristors are used,
there is more room for overload if required . However with the availability of 6 inch thyristors which are capable
of handling 4000 Amps, the overload is not an issue anymore. Therefore this is not a problem.
The size and the weight of the converter transformers, are quite manageable here, the typical single phase two winding
will be in the order of 278 MVA. From spare transformers point of view two spare units are needed per station
because of star and delta winding wise connectivity.

9. Fig 3 Single phase 2 winding transformer, courtesy ABB
For any insulation type problems the poles can be operated at the typical 0.8 pu DC voltage.In this configuration the
converters can be built at different locations. In principle the two bipole scale be separated by any distance but a
reliable communication system between parallel converters is a must for smooth recovery from faults and proper
current sharing between converters. This is similar to a multi-terminal DC system. For the loss of a converter, metallic
return operation cannot be used for full load operation and therefore ground current has to be accepted.
However, in case of lower transmitted power level, the ground current can be minimized with proper control
philosophy by making different power order between the remaining operating poles.
Fig 4: Simple diagram of Entire project.
The next lesson describes the level of fault indication and how to interfere from the available data
through TDR.

10. 1.3 HVDC line Fault Analysis:
1.3.1 Time domain reflectometer (TDR)
A time domain reflectometer, TDR, or pulse echo meter is a device which can measure distances to changes in the
impedance of a conductor. The technique is based upon the principle of travelling waves. A short rise time pulse is
injected in the conductor and it is partly reflected by impedance discontinuities in the line. The trace is then displayed
on an oscilloscope screen. By measuring the travel time t between the pulse is sent and a reflection is received it’s
possible to calculate the distance to the discontinuity that caused the reflection. To calculate the distance to the fault
the wave propagation speed vp has to be known. The wave propagation speed for an overhead transmission line is
close to the speed of light and can be calculated by equation (1), where L is the inductance and C is the capacitance
per unit length. Then the distance d to the fault is given by equation (2). The wave propagation speed can also be
measured with a known length of the line by extraction from equation (2), this will give the exact propagation speed
of the conductor.
VP=
√
……………………………….(1)
D=
.
…………………………………(2)
By inspecting the waveform of the reflection it’s possible to determine what type of fault caused the reflection. a short
circuit is represented by a negative reflection and an open circuit represented of a positive reflection. For a high
resistance shunt fault it’s likely that the amplitude of the reflection is too small to be detectable. To resolve this
problem some TDR units have a storage function so that an old trace can be compared with a new one, there
deviations between the two traces can point out a fault
1.3.2 Low resistance to ground
Figure 1.3.2 (a) Low resistance ground fault at 5 km Tt = 33,0 μs.
Figure 1.3.2 (b) Low resistance ground fault at 25 km Tt = 165,0 μs

11. Figure 1.3.2 (c) Low resistance ground fault at 45 km Tt = 299,0 μs
1.3.3 High resistance to ground
Figure 1.3.3 (a) High resistance ground fault at 5 km Tt = 33,0 μs
Figure 1.3.3 (b) High resistance ground fault at 25 km Tt = 166,0 μs
Figure 1.3.2 (c) High resistance ground fault at 45 km Tt = 298,5 μs
With these results /display we could able to find what type of fault and where it occur, and how much it voltage
dips which leads to the Overload of the system. And the next lessons gives the total description with
Mathematical analysis to the relation of Voltage dip to Multi Infeed system.

12. 2.Multi-Infeed Stability Issue
2.1 Maximum Power Curve (MPC)
J.D.Ainsworth first introduced the Maximum Power Curve methodology, widely used for HVDC engineering study.
General definition:
For a given AC system impedance and other parameters of the AC/DC system shown in Fig. 2.1.1, there will be a
unique Pd/Id characteristic, shown in Fig. 2.2, provided the starting conditions are defined as in the following
paragraph. Additionally, it is assumed that Id changes almost instantaneously in response to the change of α of the
rectifier; for example, due to a change in current order. All other quantities- AC system emf, γ (minimum) of the
inverter, tap-changers, Automatic Voltage Regulation (AVR), and the value of shunt capacitors and reactors-are
assumed not to have changed. When considering the inverter power capability, it is also assumed that the rectifier
provides no limitation to the supply of DC current at rated DC voltage.
Each subsequent point is calculated by steady-state equations. These “quasi-steady-state” characteristics give a good
indication of dynamic performance.
The starting conditions are defined to be as follows:
Pd = 1.0 pu, Ud = 1.0 pu, UL = 1.0 pu, and Id = 1.0 pu.
(Pd = DC power; UL = AC terminal voltage-i.e., converter transformer line-side voltage; Ud = DC voltage of the
inverter; and Id = DC current.)
Fig. 2.1.1. Simplified representation of a DC link feeding an AC system with shunt capacitors (Cs) and
synchronous compensators (SCs) (if any) at converter station busbars.
Fig. 2.1.2 Maximum Power Curve for γ minimum
If the inverter is operating at minimum constant extinction angle γ,
the resulting curve will represent maximum obtainable power for
the system parameters being considered. This curve is termed the
Maximum Power Curve (MPC). Any power can be obtained below
MPC by increasing α and γ, but power higher than MPC can be
obtained only if one or more system parameters are changed-e.g. by
reduced system impedance, increased system emf, larger capacitor
banks, etc.
A similar MPC curve can be obtained for the rectifier at minimum constant α. An MPC exhibits a maximum value,
termed Maximum Available Power (MAP) as can be seen in Fig. 2.1.2 The increase of the current beyond MAP
reduces the DC voltage to a greater extent than the corresponding DC current increase. This could be counteracted by
changing the AC system conditions-e.g. by controlling the AC terminal voltage. It should be noted that dPd/dId is
positive for operation at DC currents smaller than IMAP, the current corresponding to MAP; dPd/dId is negative at
DC currents larger than IMAP.
To characterize system, Short Circuit Ratio (SCR), Effective Short Circuit Ratio (ESCR) and
Critical Effective Short Circuit Ratio (CSCR) are defined.

13. SCR is often defined by:
SCR=
Where S is the AC system three-phase symmetrical short-circuit capacity (MVA) at the converter terminal AC bus
with 1.0 p.u. AC voltage, and Pd1 is the rated DC terminal power (MW).
ESCR is defined as:
ESCR =
Where Qc is the amount of reactive power compensation installed at inverter bus terminal.
CSCR is defined as the corresponding SCR, when the rated values of Pd, Id, Ud, and V (all at 1.0 p.u.) correspond to
the maximum point of Maximum Power Curve. It represents a borderline when operating at γ constant, as the ratio
dPd/dId changes its sign.
SCR =
.
; ESCR = ;
2.2 MPC Application to Simple Model:
In order to understand and get some insights into SCR, ESCR, CSCR, MPC and their relationships, two simple
systems have been studied: one is a simplified single HVDC link; the other is a simplified single HVDC link with an
AC line in parallel.
2.2.1 Single HVDC link model (configuration A)
.
Fig. 2.2.1 is the simplified diagram of single HVDC link, named configuration A
fig 2.2.2 a & b courtesy: Feng Wang & Yu Chen,Supervisor: Mr. Paulo Fischer de Toledo,PS/G/DC/TST
Department Power System, ABB, Ludvika.
The following conclusions can be obtained after analyzing the results above:
1. Before MAP in MPC, DC power increases as DC current increases.
2. From the V-I curve, it is possible to observe that the voltage decreases with the increase of DC current. This
is mainly due to the increase of reactive power consumption of the converter. The lower SCR, the higher the
voltage drop;
3. There is a certain power stability margin, as long as the short circuit ratio is larger than 1.6,CSCR;
4. The larger the SCR, the larger the stability margin;
5. The lower SCR, the lower MAP;
6. The HVDC link should always operate before MAP point, for stability reasons.

14. 2.2.2 Single HVDC link with AC line in parallel (configuration B)
Here Zeq=
( ).
; z’eq= +
= − ; = − ; ESCR=
.
Fig 2.2.3 a & b courtesy: Feng Wang & Yu Chen,Supervisor: Mr. Paulo Fischer de
Toledo,PS/G/DC/TST Department Power System, ABB, Ludvika.
The reason is that, in configuration B, the converters at the rectifier and inverter terminals of the HVDC link are now
coupled by the parallel AC line. This means that the rectifier converter slightly affects the operating condition of the
inverter and lowers the Maximum Power Curve as shown in the figures.
2.3 Interaction indices for multiinfeed HVDC System:
Project Length
1
(in
km)
Power (in
MW)
No. of
poles
DC
voltage(in
kV)
Converter
locations
2
HVDC
Rihand-Delhi 814 750 1 500
Rihand/
Dadri
Rihand-Delhi 814 1500 2 ±500
Rihand/
Dadri
Chandrapur-Padghe 752 1500 2 ±500
Chandrapur
/
Padghe
East-
South
Interconne
ctor II
1450 2000 2 ±500
Talcher/
Kolar
East-
South
Interconne
ctor II
upgrade
1450 2500 2 ±500
Talcher/
Kolar
Ballia-Bhiwadi 800 2500 2 ±500
Ballia/
Bhiwadi
NEA 1728 6000 2 ±800
Biwanath
chariali/Ali
purduar/
AGRA
Table 1. All existing Hvdc power/voltage/ location

15. 2.3.1 Multi Infeed Interaction Factor (MIIF):
Critical to the planning of HVDC is the real and reactive power interchange between the HVDC system and the
AC system to which it is connected. HVDC Control systems can provide a degree of optimization, but the
inverter AC voltage waveform is paramount. An indicator based on the observed AC voltage change at one
inverter AC bus for a small AC voltage change at another inverter bus provides a first level indication of the
degree of interaction between two HVDC systems. This interaction factor is called the Multi Infeed Interaction
Factor and is defined mathematically as:
=
∆ %
1%∆
where, ΔV2 % is the percentage bus voltage change at converter2 for an inductive fault at converter1 and V1 is
the AC bus voltage at inverter 1. Inverter AC busses electrically far apart will have MIIF values approaching
zero, while MIIF values approaching unity indicate AC busses that are very close.
2.3.2 Multi Infeed Effective Short Circuit Ratio (MIESCR):
The stronger the AC system, as reflected in the short circuit level, generally the better is the HVDC
performance. Most systems plan for an ESCR level above 2.0 at rated power.
=
−
+ ∑ ∗ &
MIESCRi = Multi Infeed Effective Short Circuit Ratio at inverter ‘i’
SCC MVAi = Short Circuit Capacity at inverter ‘i’
Qfilteri = Total MVAR of the filter at inverter ‘i’
Pdci= DC Power of the link ‘i’
MIIFji = MIIF of the inverter ‘j’ with respect to inverter ’i’
Pdcj = DC Power of the link ‘j’
Where MIESCR is the multiinfeed definition of ESCR and the subscript ‘j’ refers to all other HVDC links in
electrical proximity. By this definition, an HVDC link may be embedded in a relatively weak MIESCR system,
say around two, whereas a conventional calculation ESCR might indicate that the system is relatively strong at say
four or five.
Inverter SCC in
MVA
Q filter in
MVAR
Pdc in
MW
MIIF ESCR MIESCR
Agra Bhiwadi Dadri
Agra 21839 1800 3000 1 0.568 0.094 6.68 4.771
Bhiwadi 15876 1685 2500 0.304 1 0.79 5.676 3.051
Dadri 28324 690 1500 0.294 0.298 1 18.423 13.96
Table 2: MIIF Matrix for the three inverters Agra, Bhiwadi and Dadri courtesy Central power research Bangalore.
MIIF values range from zero to one with zero implying infinite electrical separation and one implying on the
same bus. Diagonal elements of the MIIF matrix are unity. MIIF less than 0.2 indicates there is no interaction
between the inverters and no need to analyze further. If MIIF lies between 0.2 and 0.4 it is found that there is no
Serious interaction and if MIIF greater than 0.5 lot of interaction between the inverters and measures to prevent it are
to be incorporated in the system. Thus for a dip in voltage at Agra & Bhiwadi, there is no dip in voltage at Dadri.
Thus there is no interaction of Dadri inverter with Agra and Bhiwadi. Also the MIIF values at Bhiwadi for a
voltage dip at Agra indicate that there is considerable interaction between Agra and Bhiwadi inverter
It is interesting to observe that in the above table, the dominating influence the large HVDC link is having on
the smaller link resulting in a dramatically different value of MIESCR to its ESCR. The system characteristics at
inverters are mostly defined by the presence of other HVDC links. It can also be noted that MIESCR collapses into
conventional definition of ESCR for single infeed HVDC system. Among the three inverters MIESCR at Bhiwadi is
less which is 3.0548 making it sensitive for any kind of faults in nearby inverters as well as in AC systems.

16. 2.3.3 Transient small signal HVDC stability analysis:
Fig 2.3.3 (a) single line for both HVDC and AC line to Generator fig 2.3.3 (b) similar to (a) direction change for Load .
So, first analysing 2.3.3 (a), as both yield same equations except the direction change.
In the context of power system engineering ,
the swing equation has been utilized to consider the synchronized operation:
+ + sin = …………………….(i.i)
The equation represents the synchronized operation of one generator connected to an infinite bus via transmission
lines and transformers. δ denotes the rotor position compared with the infinite bus, D the damping coefficient in the
generator, b the critical value of power transmission, and p. the mechanical power input of the generator. The swing
equation (1.1) has the nonlinear restoring force b*sin( ) which corresponds to electric power output of the generator.
Namely, the nonlinearity originates from the electric power balance relation between the generator and the infinite
bus.
Pe(ac)= sin − ∈ cosΩ
The addition term is exiting Power,
But total Pe=Pe(ac)+Pe(dc)
As = => = − + − ( + )
This swing equation system is relevant to analysing the transient dynamics of the ac/dc power system under the
assumption that the dc link is ideally operated.
Just case D=0, Pm=Pedc, ∈=0 ..=> = sin
We get the solution as ( ) = ± ( √ ), But in stability point 10< <40,
as the case for steady and stable state there is a large fluctuant in the
AC line connected to that HVDC system, for the case of Multiple
HVDC inverter side, a dip in one of Hvdc yields a great peaks of
load angle varies occur, leads to a dangerous Stability problems.
By observing graph can easily conclude that the rise of load angle is
more like exponential at initial stage, hard to control on real time
analysis.
The range of Y in degrees
is [− , ]
(Graphing Calculator 3d).
Fig 5 graph of ( ) i.e load angle with time
√ = = ( )

17. If the Pm-Pedc< 0, ∈ > 0, we expect the bifurcated graph as,
Conclusion and Future work:
This project presented a case study concerning the operation performance of multi-infeed HVDC system. The
technical approaches used in this study include power flow analysis, quasi-static modal analysis, transient
stability simulation analysis and dynamic performance studies. In summary satisfactory operation performance
can be expected for the studied multi-infeed HVDC transmission system. The identified potential problems due
to extreme contingencies can be effectively mitigated by installing adequate series and shunt reactive power
compensation devices at the critical AC transmission lines and interface area. Improved system performance can
be achieved by implementing advanced controls such as fast power flow controllers.
The technical approaches presented in this paper may be used as a general guideline of future multi-infeed
HVDC transmission system studies. However, it should be mentioned that the results obtained in this study are
considered as indicative of the expected system performance since additional network expansion projects have
been proposed
Applying Remedial Measures and Future work:
,It has been verified that the ‘interface area’ is the critical area in the NORTH HVDC interconnection system. In
order to improve the system performance, a remedial measure would be to add reactive power support devices
on some of the busses in that area. This means that these devices would support the most critical area of the
system. Two important considerations should be pointed out. First, it is advisable that those devices should have
fast response to changes in the system. This means that an SVC or STATCOM or fast switching shunt devices
like capacitor banks and shunt reactors should be used. Second, considering that this ‘interface area’ is a rather
big area, it is convenient to consider several reactive power support devices located on different busses .
Study on the original network, instead of the equivalent network, the analysis of CFII i.e Commutation Failure
Immunity Index, One of the major concerns in design of HVDC system is the susceptibility to Commutation Failure
(CF). Repeated CF generally causes over current in the valves and also delays the restart of the HVDC system after
fault clearing. In the multiinfeed HVDC system, both converters connect into the same AC network and the
Commutation Failure at one converter could affect the other converter. sensitivity of different inverters and the
recovery performance of different links after major disturbances under normal and contingency system
operating conditions. The purpose of the study is to verify if, due to these phenomena of concern, it might be
needed to develop coordinated recovery control strategy to achieve acceptable performance of multiple HVDC
links. Simulation can be done in PSCAD with the available data from respective authority(Power Grid /Posoco),
and preplanning and protecting our Nation without any further Black-out and Availability 99.999% as our
Motive.

18. References:
1. Paulo Fischer de Toledo, et al, “Multiple Infeed Short Circuit Ratio – aspects related to multiple HVDC into
one AC Network” ; paper presented in Dailian 2005 Conference, China
2. Feng Wang & Yu Chen “Voltage/Power Stability Study upon Power System with Multiple-Infeed
Configuration of HVDC Links Using Quasi-static Modal Analysis Approach” Power System, ABB, Ludvika,
mar. 2006
3. Andreas Hermansson “Simulation of line fault locator on HVDC Light electrode line” Aug 2010
4. Yoshihiko Susuki “Transient Dynamics and Stability Boundaries in Electric Power System with DC
Transmission” PHD thesis Nov 2006
5. MU Zi-long “Research on Harmonic Instability Problem at Sending End of UHVDC Power Transmission
Project From Yunnan to Guangdong” oct 2008
6. Victor F. Lescale “Challenges with Multi-Terminal UHVDC Transmissions” oct 2008.
7. EPRI “Advanced HVDC Systems at ±800 kV and Above” Nov 2007.